Optimizing electromagnetic telemetry transmissions

ABSTRACT

An electromagnetic telemetry system adjusts telemetry parameters which may include carrier frequency, signal amplitude and/or data encoding protocol to achieve reliable data transmission and to conserve power. In some embodiments, sweep signals transmit a range of carrier frequencies and the parameters are determined in part by analyzing the received sweep signals. In some embodiments, different parameters are selected automatically based on a mode of drilling.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.14/914,050, which is a 371 of PCT International Application No.PCT/CA2014/050825 filed 28 Aug. 2014, which claims the benefit under 35U.S.C. § 119 of U.S. Application No. 61/870,968 filed 28 Aug. 2013, allentitled OPTIMIZING ELECTROMAGNETIC TELEMETRY TRANSMISSIONS and all ofwhich are hereby incorporated herein by reference for all purposes.

TECHNICAL FIELD

This application relates to subsurface drilling, specifically to methodsand apparatus for communicating data to and from downhole equipment byelectromagnetic telemetry. Embodiments are applicable to drilling wellsfor recovering hydrocarbons.

BACKGROUND

Recovering hydrocarbons from subterranean zones typically involvesdrilling wellbores.

Wellbores are made using surface-located drilling equipment which drivesa drill string that eventually extends from the surface equipment to theformation or subterranean zone of interest. The drill string can extendthousands of feet or meters below the surface. The terminal end of thedrill string includes a drill bit for drilling (or extending) thewellbore. Drilling fluid, usually in the form of a drilling “mud”, istypically pumped through the drill string. The drilling fluid cools andlubricates the drill bit and also carries cuttings back to the surface.Drilling fluid may also be used to help control bottom hole pressure toinhibit hydrocarbon influx from the formation into the wellbore andpotential blow out at surface.

Bottom hole assembly (BHA) is the name given to the equipment at theterminal end of a drill string. In addition to a drill bit, a BHA maycomprise elements such as: apparatus for steering the direction of thedrilling (e.g. a steerable downhole mud motor or rotary steerablesystem); sensors for measuring properties of the surrounding geologicalformations (e.g. sensors for use in well logging); sensors for measuringdownhole conditions as drilling progresses; one or more systems fortelemetry of data to the surface; stabilizers; heavy weight drillcollars; pulsers; and the like. The BHA is typically advanced into thewellbore by a string of metallic tubulars (drill pipe).

Modern drilling systems may include any of a wide range ofmechanical/electronic systems in the BHA or at other downhole locations.Such electronics systems may be packaged as part of a downhole probe. Adownhole probe may comprise any active mechanical, electronic, and/orelectromechanical system that operates downhole. A probe may provide anyof a wide range of functions including, without limitation: dataacquisition; measuring properties of the surrounding geologicalformations (e.g. well logging); measuring downhole conditions asdrilling progresses; controlling downhole equipment; monitoring statusof downhole equipment; directional drilling applications; measuringwhile drilling (MWD) applications; logging while drilling (LWD)applications; measuring properties of downhole fluids; and the like. Aprobe may comprise one or more systems for: telemetry of data to thesurface; collecting data by way of sensors (e.g. sensors for use in welllogging) that may include one or more of vibration sensors,magnetometers, inclinometers, accelerometers, nuclear particledetectors, electromagnetic detectors, acoustic detectors, and others;acquiring images; measuring fluid flow; determining directions; emittingsignals, particles or fields for detection by other devices; interfacingto other downhole equipment; sampling downhole fluids; etc. A downholeprobe is typically suspended in a bore of a drill string near the drillbit.

A downhole probe may communicate a wide range of information to thesurface by telemetry. Telemetry information can be invaluable forefficient drilling operations. For example, telemetry information may beused by a drill rig crew to make decisions about controlling andsteering the drill bit to optimize the drilling speed and trajectorybased on numerous factors, including legal boundaries, locations ofexisting wells, formation properties, hydrocarbon size and location,etc. A crew may make intentional deviations from the planned path asnecessary based on information gathered from downhole sensors andtransmitted to the surface by telemetry during the drilling process. Theability to obtain and transmit reliable data from downhole locationsallows for relatively more economical and more efficient drillingoperations.

Telemetry data may include data regarding a current orientation of adrill bit (sometimes called “tool face” data). Telemetry information mayinclude data retrieved from sensors which monitor characteristics of theformations surrounding the wellbore (“logging” data). Telemetryinformation may include information regarding the drilling itself (e.g.information regarding downhole vibration, characteristics of thewellbore being drilled, flow rate of drilling fluid, downhole pressureand the like).

There are several known telemetry techniques. These include transmittinginformation by generating vibrations in fluid in the bore hole (e.g.acoustic telemetry or mud pulse (MP) telemetry) and transmittinginformation by way of electromagnetic signals that propagate at least inpart through the earth (EM telemetry). Other telemetry techniques usehardwired drill pipe, fibre optic cable, or drill collar acoustictelemetry to carry data to the surface.

Advantages of EM telemetry, relative to MP telemetry, include generallyfaster baud rates, increased reliability due to no moving downholeparts, high resistance to lost circulating material (LCM) use, andsuitability for air/underbalanced drilling. An EM telemetry system cantransmit data without a continuous fluid column; hence it is useful whenthere is no drilling fluid flowing. This is advantageous when a drillcrew is adding a new section of drill pipe as the EM signal can transmitinformation (e.g. directional information) while the drill crew isadding the new pipe.

As EM transmissions are strongly attenuated over long distances throughearth formations, EM telemetry can have the disadvantage of undesirablyshort range. Also, EM telemetry can require a relatively large amount ofelectrical power, especially where one is attempting EM telemetry from adeep wellbore or from within a formation that has relatively highelectrical conductivity.

A typical arrangement for electromagnetic telemetry uses parts of thedrill string as an antenna. The drill string may be divided into twoconductive sections by including an insulating joint or connector (a“gap sub”) in the drill string. The gap sub is typically placed at thetop of a BHA such that metallic drill pipe in the drill string above theBHA serves as one antenna element and metallic sections in the BHA serveas another antenna element. Electromagnetic telemetry signals can thenbe transmitted by applying electrical signals between the two antennaelements. The signals typically comprise very low frequency AC signalsapplied in a manner that encodes information for transmission to thesurface. Low frequencies are used because higher frequency signals areattenuated much more strongly than low frequency signals. Theelectromagnetic signals may be detected at the surface, for example bymeasuring electrical potential differences between the drill string or ametal casing that extends into the ground and one or more ground rods.

There is a demand for reliable and effective telemetry. There is aparticular need for high performance EM telemetry systems.

SUMMARY

This invention has a number of aspects. One aspect provides methods forEM telemetry. Some such methods include dynamically adjusting thecarrier frequency and/or signal amplitude of EM telemetry signals toachieve performance goals. The performance goals may, for example,include one or more of a desired data rate and a desired powerconsumption. Another aspect provides EM telemetry systems and theircomponents. For example, one aspect provides a controller for an EMtelemetry system. Another aspect provides a downhole EM telemetry unit.Another aspect provides a complete EM telemetry system. Another aspectprovides a drill string comprising a plurality of downhole EM telemetrysystems.

An example aspect provides a method for downhole electromagnetic (EM)telemetry in a downhole drilling operation. The method comprises sendinga set of EM sweep signals from a downhole EM telemetry system located ata downhole location to an uphole system located at a surface location.The set of EM sweep signals includes signals of a plurality of differentfrequencies. The method determines whether each of the EM sweep signalsis received at the uphole system and, for the EM sweep signals received,measures parameters of the received EM sweep signals. The parameterscomprise at least one of signal strength and signal-to-noise-ratio.Based at least in part on the EM sweep signals received and theparameters measured, the method determines a protocol for downhole datatransmission, the protocol specifying protocol parameters including oneor more of signal frequency, signal amplitude, and data encoding scheme;and configures the downhole EM telemetry system to transmit data to theuphole system using the protocol.

In some embodiments, the data encoding scheme comprises a number ofcycles of EM signals to use for encoding symbols for transmission; anddetermining the protocol comprises setting the number of cycles to beused for encoding signals for transmission.

In some embodiments, the method comprises determining a mode of thedrilling operation and determining the protocol based at least in parton the mode of the drilling operation. For example, different protocolsmay be used depending on whether the wellbore is quiet (no flow and norotation of the drill string), operating in a sliding mode (flow on butno or limited rotation of the drill string), or operating in a full ondrilling mode (flow on and the drill string is rotated from thesurface). In some embodiments, each mode of the drilling operation isassigned a pre-set protocol.

In some embodiments, the protocol is determined at the uphole system bya processor and the protocol is communicated to the downhole EMtelemetry system using a downlink transmission system. The protocol mayoptionally be determined at the uphole system by user input incombination with the processor.

In a non-limiting example embodiment, a set of pre-set protocols arestored in the downhole EM telemetry system and determining the protocolfor downhole data transmission comprises: based at least in part on oneor more of a mode of drilling operation, the EM signals received, andthe parameters measured, generating at the uphole system an indexidentifying one of the pre-set protocols stored in the downhole EMtelemetry system; communicating the index to the downhole EM telemetrysystem using a downlink transmission system; and selecting one of thepre-set protocols stored in the downhole EM telemetry system based atleast in part on the index communicated.

Some embodiments send periodic sweeps of EM sweep signals from thedownhole EM telemetry system to the uphole system; detect the EM sweepsignals at the uphole system and; based on the detected EM sweepsignals, determine whether to adjust one or more of the protocolparameters. Such embodiments may operate to conserve electrical power atthe downhole EM telemetry system by switching to a more energy-efficientprotocol when the detected EM sweep signals indicate that the moreenergy-efficient protocol would provide adequate performance. As anexample, a more energy-efficient protocol uses a higher frequency and/orfewer cycles per symbol to achieve a higher data rate, such that a givenamount of data can be transmitted uphole in a shorter period ofoperation of the downhole EM telemetry system, and/or selects afrequency that can be received at the surface when transmitted using alower transmission amplitude.

Another example aspect provides an EM telemetry system for communicatingsignals in a wellbore between a surface location and a downholelocation. The EM telemetry system comprises: a signal generatorconfigured to send a sweep of EM sweep signals at the downhole location;a receiver configured to receive the EM sweep signals at the surfacelocation; and a processor coupled to the receiver and the signalgenerator, the processor configured to determine whether each of the EMsweep signals in the sweep is received at the receiver and, for each ofthe EM sweep signals received, record parameters of the EM sweep signal,the parameters comprising at least one of signal strength andsignal-to-noise ratio, the processor further configured to determine aprotocol for data transmission between the downhole location and thesurface location, the protocol comprising protocol parameters includingone or more of signal frequency, signal amplitude, and data encodingscheme; and a downlink transmission system coupled to the processor andthe signal generator, the downlink transmission system communicating thedetermined protocol to the signal generator.

Another example aspect provides a downhole EM telemetry systemcomprising: a control circuit, an EM signal transmitter; a plurality ofEM telemetry protocols; and one or more sensors. The control circuit isconfigured to determine a state of a drilling operation based on signalsfrom the one or more sensors and to apply one of the plurality of EMtelemetry protocols for transmission of data by the EM signaltransmitter based on the determined state of the drilling operation.

Another example aspect provides a method for downhole electromagnetic(EM) telemetry in a downhole drilling operation. The method comprises,in response to determining that a drilling operation is in a quiet modewherein a flow of drilling fluid is off and a drill string is not beingrotated, configuring a downhole EM telemetry system to transmit data toan uphole system using a first protocol that transmits data at a firstdata rate. The method transmits first data using the first protocol. Insome embodiments the first data is survey data. After transmitting thefirst data, the method configures the downhole EM telemetry system totransmit data to the uphole system using a second protocol thattransmits data at a second data rate lower than the first data rate andtransmits second data using the second protocol. In some embodiments,determining that the drilling operation is in the quiet mode comprisesprocessing signals the one or more sensors at the downhole system. Thesensors may include a fluid flow sensor and a rotation or directionsensor in some embodiments.

Further aspects of the invention and features of example embodiments areillustrated in the accompanying drawings and/or described in thefollowing description.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings illustrate non-limiting example embodiments ofthe invention.

FIG. 1 is a schematic view of a drilling operation.

FIG. 2 shows an example of a sweep signal.

FIG. 3 shows an example of a sweep signal detected at the surface.

FIG. 4 is a flow chart illustrating an example method for adjusting EMtelemetry parameters.

FIG. 5 is a flow chart illustrating another example method for adjustingEM telemetry parameters.

DESCRIPTION

Throughout the following description specific details are set forth inorder to provide a more thorough understanding to persons skilled in theart. However, well known elements may not have been shown or describedin detail to avoid unnecessarily obscuring the disclosure. The followingdescription of examples of the technology is not intended to beexhaustive or to limit the system to the precise forms of any exampleembodiment. Accordingly, the description and drawings are to be regardedin an illustrative, rather than a restrictive, sense.

FIG. 1 shows schematically an example drilling operation. A drill rig 10drives a drill string 12 which includes sections of drill pipe thatextend to a drill bit 14. The illustrated drill rig 10 includes aderrick 10A, a rig floor 10B and draw works 100 for supporting the drillstring. Drill bit 14 is larger in diameter than the drill string abovethe drill bit. An annular region 15 surrounding the drill string istypically filled with drilling fluid. The drilling fluid is pumpedthrough a bore in the drill string to the drill bit and returns to thesurface through annular region 15 carrying cuttings from the drillingoperation. As the well is drilled, a casing 16 may be made in thewellbore. A blow out preventer 17 is supported at a top end of thecasing. The drill rig illustrated in FIG. 1 is an example only. Themethods and apparatus described herein are not specific to anyparticular type of drill rig.

A gap sub 100 may be positioned, for example, at the top of the BHA. Gapsub 100 divides the drill string into two electrically-conductive partsthat are electrically insulated from one another. The two parts form adipole antenna structure. For example, one part of the dipole may bemade of the BHA up to the electrically insulating gap and the other partof the dipole may be made up of the part of the drill string extendingfrom the gap to the surface.

A very low frequency alternating current (AC) electrical signal 19A isgenerated by an EM telemetry signal generator 18 and applied across gapsub 100. The low frequency AC signal energizes the earth and creates anelectrical field 19A which results in a measurable voltage differentialbetween the top of drill string 12 and one or more grounded electrodes(such as ground rods or ground plates). Electrical signal 19A is variedin a way which encodes information for transmission by telemetry.

At the surface the EM telemetry signal is detected. Communication cables13A transmit the measurable voltage differential between the top of thedrill string and one or more grounded electrodes 13B located about thedrill site to a signal receiver 13. The grounded electrodes 13B may beat any suitable locations. Signal receiver 13 decodes the transmittedinformation. A display 11 displays some or all of the receivedinformation. For example, display 11 may display received measurementwhile drilling information to the rig operator.

Whether or not EM telemetry transmissions from a downhole source can bereliably detected at the surface can depend on many factors. Some ofthese factors have to do with the characteristics of the undergroundformations through which the wellbore from which the electromagnetictelemetry is being performed passes. The electrical conductivity of theunderground environment can play a major role in the effectiveness ofelectromagnetic telemetry (higher electrical conductivity, especially inthe vicinity of gap sub 100, tends to attenuate EM telemetry signals).Both the average electrical conductivity of the underground environmentas well as the way in which the electrical conductivity may vary fromplace to place can play significant roles.

Another factor that can affect electromagnetic telemetry is the depthfrom which electromagnetic telemetry is being performed. In general,electromagnetic telemetry signals become more highly attenuated as thedepth from which the electromagnetic telemetry signals are beingtransmitted increases.

Another factor that may affect the success in receiving EM telemetrytransmissions at the surface is the particular arrangement of signaldetectors provided at the surface (e.g. the particular arrangement ofgrounding rods and other apparatus used at the surface as well as thesensitivity of the circuitry used to detect EM telemetry signals).

Another factor that can affect the effectiveness of EM telemetrytransmissions is whether and how much drilling fluid is used (e.g.underbalanced drilling may use less and/or less dense drilling fluids;in air-based underbalanced drilling, the wellbore may be air-filled),the nature of drilling fluid being used (whether the drilling fluid isoil-based or water-based), and the specific characteristics of anydrilling fluid being used.

Other factors include: whether or not the wellbore is cased and, if so,how deep does the casing extend; and the inclination of the portion ofthe drill bore in which the EM telemetry signal generator is located. Itis much more challenging to achieve effective EM telemetry transmissionfrom a cased horizontal wellbore than from an uncased vertical wellbore.

Another factor that can affect the success of EM telemetry signaltransmissions is the drilling activity that is occurring at the time ofthe transmissions. For example, drilling often has a number of phases.In one phase (which typically includes the time at which a new sectionof drill string is being added or taken off of the drill string), thebore hole is quiet. Drilling fluid is not being pumped through the drillstring “pump off”. At other phases of the drilling operation, drillingfluid is being pumped through the drill string. Active drilling mayinclude different modes of operation. In some modes of operation, theentire drill string is rotating as drilling progresses. In another“sliding” mode of operation, the drill bit is rotated by a downhole mudmotor and the drill string is not rotated except as is necessary ordesirable to steer the direction in which the drill bit is progressing.Which of these modes is occurring can affect EM telemetry by creatingelectrical noise and the like.

The combination of all the above factors creates a challengingenvironment for EM telemetry, especially where it is desired to optimizethe EM telemetry to conserve electrical power and to maximize datathroughput, where desired.

In situations where EM telemetry is more difficult, for example becauseof factors such as one or more of the above (and most typically acombination of several of the above), one can adjust the nature of theEM telemetry signals to improve the reliability of the EM telemetrychannel. The characteristics of EM telemetry signals themselves canaffect their successful transmission to the surface. One characteristicthat has particular significance is the frequency at which the EMtelemetry signals alternate in polarity and/or magnitude.

In general, lower-frequency-EM telemetry signals can be successfullytransmitted from deeper locations than higher frequency-EM telemetrysignals. For this reason, EM telemetry signals typically have very lowfrequencies. For example, EM telemetry signals generally havefrequencies in the band below 24 Hertz. For example, EM telemetrysignals according to some embodiments of the invention have frequenciesin the range of about 1/10 Hertz to about 20 Hertz. The exact endpointsof these ranges are not critically important.

One advantage of the use of higher frequencies for EM telemetry is thatthe rate at which data can be encoded in higher-frequency-EM telemetrysignals is greater than the rate at which the data can be encoded inlower-frequency-EM telemetry signals. Consequently, there is a trade-offbetween increasing the likelihood that EM signals can be successfullytransmitted from a given depth by using very low frequencies andmaintaining an increased data rate by using higher frequencies.Furthermore, if the frequency is too high, then the EM signals will beso strongly attenuated that no practical detector could pick them up atthe surface.

Selection of carrier frequency for EM telemetry signals can haveconsequences beyond the amount of time required to transmit a certainamount of data to the surface. For example, transmitting at higherfrequencies may significantly affect the amount of electrical powerrequired to transmit a certain amount of data. One reason for this isthat if data can be transmitted quickly, then, after the data has beentransmitted (or in other periods during which it is not necessary to betransmitting data), certain circuits may be shut down to conserveelectrical power. In addition, since the electrical impedance seen by anEM telemetry transmitter is somewhat frequency dependent, the amount ofelectrical power required to sustain an EM telemetry signal is alsofrequency dependent to some degree. On the other hand, higherfrequencies are attenuated more strongly than lower frequencies and sohigher frequency signals may need to be transmitted at higher amplitudes(thereby requiring more electrical power).

Another factor that influences the success of EM telemetry transmissionsis the amplitude of the EM telemetry signals. Increased amplitudesignals are easier to detect at the surface. However, the amplitude ofEM telemetry signals may be limited by the capabilities of the downholeEM telemetry transmitter. For example, if the EM telemetry transmittingcircuits can deliver only up to a maximum electrical current, then theamplitude of the EM telemetry signal will also be limited.

Other limits are imposed by the maximum voltage that can be imposed bythe EM telemetry transmitter on the downhole antenna elements. Thevoltage of an EM telemetry signal may be limited by the nature of the EMtelemetry signal generator as well as its power source. In some cases,the voltage may be limited by design to being below a threshold voltagefor safety reasons. For example, in some embodiments, the voltage may belimited to a voltage of 50 Volts or less in order to reduce thelikelihood that personnel who are handling the EM telemetry signalgenerator at the surface could be exposed to electrical shocks and/or toreduce the likelihood that the EM signal generator could serve as anignition source.

The voltage that may be applied across the EM telemetry antenna elementsmay also depend on the characteristics of the gap. Typically, for alonger gap, a larger voltage may be applied without exceeding theelectrical current capabilities of the EM telemetry signal generator. Inaddition to the above, increasing the amplitude of EM telemetry signalsgenerally results in increased electrical power consumption. It istherefore desirable not to transmit EM telemetry signals that haveamplitudes much greater than necessary.

The encoding scheme used to transmit EM telemetry signals can also playa role in the success with which the EM telemetry signals can bereceived. For example, if the encoding scheme is such that it encodesinformation by, at least in part, transmitting EM telemetry signals ofdifferent amplitudes, then it may be necessary for all of the differentamplitudes, which are part of the encoding scheme, to be detectable atthe surface for the EM telemetry transmission to be successfullyreceived. If only some of the amplitudes are received at the surface, itmay not be possible to recover the transmitted information at thesurface.

As another example, different encoding schemes may use different numbersof cycles to encode symbols for transmission. For example, in low-noiseenvironments, one may be able to successfully transmit EM telemetrysymbols using an encoding scheme which transmits one symbol in twocycles of the EM telemetry signal. In higher noise environments, it maybe desirable or necessary to use an encoding scheme which transmits onesymbol in three or more cycles of the EM telemetry signal.

One aspect of the present invention provides methods and systems foroptimizing EM telemetry by automatically selecting or assisting a userin the selection of appropriate EM telemetry parameters which mayinclude one or more of: EM telemetry signal carrier frequency, EMtelemetry signal amplitude, and EM telemetry signal data encodingscheme.

Apparatus and methods according to some example embodiments of thisinvention are configured to perform and/or, when in use, are operated toperform one or more of the following (in any combination):

-   -   conduct measurements to evaluate the effectiveness of EM        telemetry transmission at different frequencies and use the        obtained information to optimize EM telemetry transmission for        one or more of data throughput and electrical power        conservation.    -   detect a current mode of drilling and automatically switch among        one or more sets of EM telemetry parameters based at least on        the detected drilling mode.    -   select and/or recommend selection of a set of EM telemetry        parameters based at least in part on a remaining amount of        electrical power.    -   transmit certain data using two or more different EM telemetry        carrier frequencies (either simultaneously or at different        times).

In some embodiments, frequency sweeps are periodically transmitted froma downhole EM telemetry signal generator (e.g. once every few minutes toonce every few hours). A frequency sweep may be triggered by time, anevent (e.g. onset of a pump-off condition) or combinations thereof.Here, ‘periodically’ does not require that there is a fixed time betweenfrequency sweeps. The time may vary somewhat. Frequency sweeps may beconducted often enough to detect significant changes in EM telemetryconditions as a downhole EM telemetry transmitter is moved along anadvancing wellbore.

A frequency sweep is an electromagnetic telemetry transmission whichtransmits at different frequencies at different times. While it is notalways advantageous to do so, in some cases, two or more frequencies aretransmitted simultaneously. Transmitting only a few frequencies at thesame time (e.g. 2 to 3 frequencies) has the advantages of allowinghigher power to be allocated to each frequency (while staying within thecurrent/voltage capabilities of an EM signal generator) as well asmaking it easier to detect signals at the different frequencies at thesurface. Differential attenuation and phase shifts between differentfrequencies transmitted through the EM telemetry signal path can makeseparating a received signal into different frequency componentsdifficult.

The sweep may cover an entire range of frequencies that the EM telemetrysystem is capable of generating or, as described further below, maytransmit only a subset of such frequencies in some embodiments. FIG. 2shows an example of a sweep 30. FIG. 3 shows an example of a sweepsignal detected at the surface.

Frequency sweep 30 shows that EM telemetry signals having a first, lowerfrequency, are transmitted in a first time period 31A, EM telemetrysignals of other frequencies are transmitted in subsequent time periods31B, 31C, 31D, and 31E.

It can be seen in FIG. 3 that the amplitude of the received signalsdrops off quickly with frequency to the point that the highest frequencysignal is not successfully received. One advantage to transmittingfrequencies in a frequency sweep one at a time is that the receivedsignal may be displayed to a user in a way that clearly shows the amountof attenuation at different frequencies and whether or not a usablesignal is being received at each frequency. FIG. 3 is an example of onepossible display. This, in turn, allows more confidence in the selectionof a frequency for EM signal transmission.

An example EM telemetry system has a frequency range of 1/10 Hertz to 16Hertz in a number of steps. For example, the system may be configured tobe capable of transmitting EM telemetry signals at 1/10 Hertz, ½ Hertz,1 Hertz, 2 Hertz, 4 Hertz, 8 Hertz, 12 Hertz, and 16 Hertz. A sweep mayconsist of a sequence of transmissions at these different frequencies.Each transmission may last for a given time, a given number of cycles,etc. In some embodiments, each frequency is transmitted for the samelength of time.

The different frequency transmissions do not need to occur in anyparticular order. They may be transmitted in order of: higherfrequencies to lower frequencies; or lower frequencies to higherfrequencies; or other arrangements that are not necessarily infrequency-order. Transmitting in order of lower frequencies to higherfrequencies has the advantage that lower frequencies are, in general,more readily received at the surface than higher frequencies.Consequently, starting a sweep at lower frequencies allows surfaceequipment to ensure that it is detecting the EM telemetry at thebeginning of the sweep. The surface equipment can then detect thequality of transmission at successively higher frequencies.

Downhole electromagnetic telemetry equipment may be configured togenerate sweeps at specified times and/or during specified phases of thedrilling operation. For example, when a “pump off” condition (alsocalled a “flow off” condition) is detected (a pump off condition may bedetected, for example, by a flow sensor or other sensor associated withthe downhole electromagnetic telemetry system), the EM telemetry systemmay automatically generate a sweep. The sweep may be generated, forexample, a few seconds (e.g. 10 to 50 seconds, in an example embodiment30 seconds) after the pump-off condition commences. A sweep may betransmitted automatically, every time the downhole EM telemetry systemdetects that the bore is quiet (both rotation and flow are off).

Surface equipment may detect some or all of the frequencies transmittedin the sweep. For each of the detected frequencies, the surfaceequipment may measure various factors such as signal strength,signal-to-noise ratio, and the like.

Based at least in part upon analysis of the received sweep signals, thesystem may set the downhole EM telemetry system to transmit data using aspecified EM telemetry protocol (a specified set of EM telemetryparameters) and/or selectively change one or more EM telemetryparameters. A protocol may, for example, specify: one or more EMtelemetry carrier frequencies and/or one or more specified EM telemetrysignal amplitudes and/or one or more EM telemetry data encoding schemes.

The location(s) where the determination is made as to what protocol willbe used by the downhole EM telemetry signal generator to transmit datamay vary in different embodiments. In some embodiments, thedetermination is made by a computer system located at the surface,either by applying algorithms, such as the algorithms described below,or by applying algorithms in combination with human input. Thedetermination may then be transmitted by some form of downlink telemetryto the downhole EM telemetry system. In some embodiments, the downholeEM telemetry system stores a set of pre-determined protocols and thedownlink telemetry transmits an index identifying one of thepredetermined protocols for use. In other embodiments, the downlinktelemetry transmits EM telemetry parameters for the protocol to be used.

The downlink transmission may be by EM telemetry but may also or insteadbe transmitted using another telemetry type. Example alternativetelemetry types that may be used for the downlink telemetry include: mudpulse telemetry, drill string acoustic telemetry, or telemetry performedby operating the drilling equipment (e.g. by rotating the drill stringand/or turning on or off the flow of drilling fluid or regulating theflow of drilling fluid in a pattern detectable by sensors at thedownhole EM telemetry signal generator).

In other embodiments, the uphole system may transmit results of thesweep to the downhole EM telemetry system. A processor at the downholeEM telemetry system may apply an algorithm to determine a protocol touse for EM telemetry based on the results of the sweep.

The protocol may be selected based on:

-   -   the set of one or more frequencies and amplitudes that can be        received at the surface under current operating conditions;        and/or,    -   a desired data rate for certain data (for example, it may be        desired to transmit “tool face” information—information        specifying the current orientation of a drill bit—using a high        data rate such that the information may be received at the        surface with low latency); and/or,    -   limits imposed by a desire to conserve electrical power and/or        an available reserve of electrical power.

For example, in a particular case it may be desired to transmit toolface information to the surface quickly. From the sweep, the system mayhave determined that no reliably detectable signal is received at thesurface for transmission frequencies of 12 Hertz or 16 Hertz. An 8 Hertzsignal may be detectable within the limits of the surface equipment(which can typically detect signals of a few hundred microvolts at thesurface). However, it may be necessary to use a large transmissionvoltage (corresponding to a relatively high power of transmission) inorder to make the 8 Hertz signal detectable at the surface. A 2 Hertzsignal may be detectable at the surface with a more moderate EM signaltransmission amplitude. The system may balance the desirability ofhaving rapid transmission of the tool face data to the surface againstthe cost in terms of power usage of transmitting that data using an 8Hertz carrier frequency.

In another example embodiment, some available EM telemetry protocols usetransmissions at two or more frequencies. The results of a sweep may beapplied in such embodiments to ascertain whether or not to use suchprotocols (e.g. if no two suitable frequencies are available, then suchprotocols may not be used) and, if so, which two or more frequencies touse for the selected protocol. For example, in a case where a sweepshows that signals at both 16 Hz and 12 Hz are cleanly received at thesurface then a dual-frequency protocol may use frequencies of 12 Hz and16 Hz. In another case, where the only available frequency that can bereliably received at the surface is ½ Hz, then a single-frequencyprotocol using ½ Hz signals may be used.

In some embodiments, the system determines a cost per bit of differentavailable frequency/amplitude combinations where the cost is expressedin terms of power consumption. Different types of data may havedifferent values. For example, tool face information may be transmittedat a higher data rate up to a threshold cost per bit whereas otherinformation which is less important to receive quickly may have a lowervalue and be transmitted using a protocol which has a lower cost perbit.

In some embodiments, one or more EM telemetry parameters areincrementally adjusted based upon results of a sweep. For example, if asweep signal is received very strongly at the surface, then:

-   -   a carrier frequency of the EM telemetry signal may be increased;        and/or    -   a data transmission protocol which yields a higher data rate at        the same or a different frequency may be switched to; and/or    -   an amplitude (voltage) of the EM telemetry signal may be        reduced.

The opposite adjustment(s) may be made where a received sweep signal isweak. Each time a sweep is conducted the system may decide whether toincrease or decrease one or more of these parameters in an incrementalway.

In some embodiments, the system is configured to first adjust afrequency to obtain an EM telemetry signal that can be effectivelyreceived. The system may start from a current frequency and drop thefrequency stepwise until reception occurs. If this does not work, thenthe system may boost the amplitude of the EM telemetry signals up to alimit in order to attempt to find the combination of frequency andsignal strength that will succeed in transmitting the signal.

FIG. 4 shows a flow chart illustrating a method 40 according to oneexample embodiment. In block 42, the system is initialized. An EM signaltransmitter is initially set to a default frequency, for example, 12Hertz or some other frequency which represents a desired operatingfrequency. Block 43 checks to see whether reception of the signal isgood. If not, block 44 determines whether the frequency can be reduced.If so, block 45A drops the frequency to a lower frequency, e.g. 4 Hertz,and the system returns to block 43 to test whether signal quality isgood.

If block 44 determines that no further frequency reduction is possible,then the method proceeds to block 44A which checks to see if the voltage(current) of the EM telemetry signal can be increased. In someembodiments, block 44A bases the determination on available batterypower. In other embodiments, a number of voltage settings are availableand block 44A determines whether or not the system is already in thehighest voltage (current) setting. If not, block 45B increases thevoltage to the next level and the method returns to block 43. If novoltage increase is possible, then block 45C indicates a change intelemetry type (for example, the system may switch over to mud pulsetelemetry).

It can be seen that, if the signal quality is not acceptable, thenmethod 40 will repeatedly switch to lower frequencies until the lowestavailable frequency is selected and will then try to increase signalamplitude until the highest available signal amplitude is selected. Ifthe signal quality is still unacceptable, then method 40 switches to analternative telemetry type (or takes an alternative action such asquitting).

If block 43 determines that the signal quality is acceptable, thenmethod 40 proceeds to block 46. Block 46 determines whether a data rateis acceptable. Block 46 may base its determination in part on the natureof the data available to be transmitted (e.g. whether the data is highpriority or low priority for transmission) as well as a predeterminedminimum data rate. If block 46 determines that the data rate isacceptable, then method 40 proceeds to block 49 which keeps the currentEM telemetry parameters. Otherwise, method 40 proceeds to block 47 whichchecks to see whether the frequency can be increased. In someembodiments, block 46 can direct execution to block 47 only where thepredetermined minimum data rate has been changed since the last timeblock 46 was executed. In such embodiments, where the minimum data ratehas not been changed then block 46 may proceed to block 49.

In some embodiments, measurements of signal to noise ratio (SNR) and/orreceived signal strength are applied to determine available data rates.For example, if SNR is low, then data rate may be limited below a datarate that could be achieved for a higher SNR. If received signal poweris low, then the data rate may also be limited (for example atransmission protocol using more cycles per bit may be required ifreceived signal power is low). FIG. 4 shows blocks 46A and 46B whichevaluate SNR and received signal power. The decision in block 46 and/orthe available frequencies in block 47 may be determined with referenceto the results obtained in blocks 46A and/or 46B. Block 46 and/or 47 maycomprise looking up suitable data rates and/or transmission frequenciescorresponding to the SNR and/or signals strength detected in blocks 46Aand 46B. In some embodiments, such lookup operations also use thecurrent transmission parameters—e.g. frequency and transmit powers tolook up appropriate data rate and/or frequencies.

If block 47 determines that the frequency can be increased, method 40proceeds to block 48 which increases the frequency to be used for EMtelemetry. In some embodiments, block 48 may be executed enough times toincrease the frequency to 16 Hz or even higher.

FIG. 5 shows a method 50 according to a further alternative embodimentof the invention which includes additional steps for adjusting thesignal transmission protocol. In FIG. 5, block 52 determines whether areceived signal is sufficiently strong. Block 52 may, for example,comprise determining a bit energy (which may be given by a product ofbit duration and received signal power). If the received signal is notstrong enough (e.g. has a bit energy below a threshold), block 53decreases frequency of the transmitted signal and/or increases amplitudeof the transmitted signal. Block 53 may, for example, work as shown inblocks 44 to 45C of method 40. In some embodiments, block 53 firstattempts to achieve an acceptable received signal by decreasingfrequency and then increasing signal amplitude.

If block 52 determines that signal quality is acceptable, then block 54determines whether strength of the received signal is unnecessarilyhigh. If so, then block 55 is executed. Block 55 increases the frequencyof the transmitted signals and/or reduces amplitude of the transmittedsignals. Block 55 may operate similarly to block 53. Block 55 may workby first trying to reduce the amplitude of the transmitted signal andthen trying to increase frequency of the transmitted signal or may dothe reverse. In some embodiments, block 55 may operate by trying toincrease frequency until a maximum frequency is reached.

If block 54 determines that signal strength is not excessive, then block56 checks to see whether the data rate is acceptable. If not, then block57 checks to see if the number of cycles per symbol could be reduced. Insome embodiments, block 57 checks to see whether the number of cyclesper symbol can be reduced without reducing bit energy below a threshold.If so, then the transmission protocol is changed to reduce the number ofcycles per symbol in block 58B. Otherwise, the frequency is increased(if possible) in block 58A. If block 56 determines that the data rate isacceptable, then the current EM telemetry parameters are kept in block59.

In some embodiments, the effectiveness, useful frequencies, and so onfor EM telemetry may be readily predictable from experience in drillingprevious wellbores under similar conditions. In such embodiments, it maybe acceptable to inhibit sweeps for a certain portion of the drillingoperation (where the EM telemetry characteristics can be readilypredicted from previous experience). In such embodiments, for example, asweep may be performed once every N pump off conditions (with N being aninteger).

In an example embodiment, in a development well which is expected tohave very similar characteristics to a previously drilled exploratorywell or another previously-drilled development well, the downhole EMtelemetry system may be configured to automatically select an EMtelemetry protocol based on depth according to a predetermined schedule(depth may be determined, for example, by a reading from a pressuresensor). The EM telemetry system may periodically, but much more rarelythan might otherwise be done, transmit a sweep to the surface. Thedetection of the sweep at the surface may be compared to expectedreadings and the result used to adjust a schedule of changing EMtelemetry protocols with depth.

In some embodiments, the EM telemetry transmission frequency and/orother elements of the EM telemetry protocol are determined based atleast in part on a current mode of drilling. For example, different EMtelemetry protocols may be used depending upon whether there is pump offcondition and, if not, whether drilling is being performed in a slidingmode or in a rotating mode at which the entire drill string is beingrotated.

For example, under certain conditions EM telemetry may be performed at:16 Hertz when the well is quiet (no flow “pump off” condition); 8 Hertzwhile drilling under sliding conditions; and 2 Hertz during “full on”drilling while the drill string is rotating. The specific frequenciesused in different drilling modes may be different in othercircumstances. These specific frequencies may, for example, bedetermined in part based on results of a sweep.

In an example embodiment, a maximum frequency to use is determined frominformation transmitted during a sweep. The maximum frequency may beused during times when the wellbore is quiet (no flow, no rotation ofthe drill string). Lower frequencies may automatically be selected foruse when the drill string is active. Different frequencies may be useddepending on whether the drill string is being operated in a slidingmode (flow on without significant rotation of the drill string) or in afull on drilling mode (flow on and the drill string is rotating). Thesedifferent frequencies may be selected automatically. For example, sensorreadings may be obtained which indicate whether drilling fluid isflowing and whether the drill string is rotating. Communicationfrequencies may be selected based on the sensor readings. A firstfrequency, F1, may be selected in the case of no flow and no rotation. Asecond frequency F2 may be selected in the case of flow but no rotation.A third frequency F3 may be selected in the case of flow and rotation.The frequency selected for use when a sliding mode is detected may behigher than the frequency selected for use when a full on drilling modeis detected. In some cases F1>F2>F3.

In some embodiments, more frequencies are used in some drilling modesthan in others. For example, when the wellbore is quiet, two or morefrequencies may be used to transmit data and during full on drillingonly one frequency may be used to transmit data.

Embodiments of the invention may employ any suitable scheme for encodingdata in an EM telemetry signal. One such scheme is QPSK (quadraturephase shift keying). Another scheme is BPSK (binary phase shift keying).A PSK (phase-shift keying) encoding scheme may use a number of cycles(at the current frequency) to transmit each symbol. The number of cyclesused to transmit each symbol may be varied. For example, in low-noiseenvironments, one may be able to successfully transmit EM telemetrysymbols using two cycles per symbol. In higher noise environments, itmay be desirable or necessary to use three cycles (or more) to transmiteach symbol. In some embodiments, the number of cycles to be used toencode a symbol is selected based on a measured signal-to-noise ratio(SNR) in a recent sweep. Other encoding schemes include FSK(frequency-shift keying), QAM (quadrature amplitude modulation), 8ASK (8amplitude shift keying), APSK (amplitude phase shift keying), etc.Schemes which use any suitable combinations of changes in phase,amplitude, timing of pulses and/or frequency to communicate data may beapplied.

In some embodiments, different encoding schemes are automaticallyselected based on the drilling mode. For example, fewer cycles persymbol may be used for telemetry during pump off conditions than areused for telemetry during full on drilling. Since the current drillingmode is readily determined both at the downhole EM telemetry system andat the surface, it is not necessary to provide explicit communicationbetween the downhole telemetry system and the surface to indicate thatEM telemetry transmissions are using another EM telemetry protocolbecause a drilling mode has changed.

In some embodiments, the protocol used for EM telemetry is specified ina configuration file at the downhole EM telemetry system. Downholesensors may provide readings to the EM telemetry system. For example,the downhole telemetry system may have access to readings from arotation sensor (any sensor that detects rotation of the drill string)and a flow sensor that detects the flow of drilling fluid. Based on theoutputs from these sensors, the EM telemetry system can determinewhether the drill string is quiet (no rotation detected, no flowdetected) or whether the drill string is operating in a sliding mode (norotation detected but flow detected), or whether the drill string isoperating in a full on drilling mode (both rotation and flow aredetected). The downhole system may automatically switch betweendifferent configuration files depending upon the readings from thesensors.

Information explaining how the signal is encoded may be already known atthe surface equipment or may be transmitted to the surface equipmentfrom the downhole EM telemetry system. For example, the datatransmission protocol may include a header with an ID included in theheader that indicates which EM telemetry protocol (or which set of EMtelemetry protocols) is being used to encode the data (and therefore,how the data should be decoded by the surface equipment). The header maybe transmitted in an easy to decode format, such as, for example, BPSK.

In some embodiments, the downhole EM telemetry system automaticallywaits for a downlink signal after a sweep has been conducted. Thedownlink signal may, for example, specify an EM telemetry protocol touse. If a downlink signal is not detected, the downhole EM telemetrysignal may automatically revert to a default ‘worst case’ protocol. Thedefault protocol may, for example, specify a very low frequency, forexample, less than ½ Hertz or less than 0.1 Hertz, or even as low as afew hundredths of a Hertz (in order to maximize the possibility that thetransmitted signals will be received at the surface).

In some embodiments, the same data is transmitted by EM telemetry(either from the surface or from a downhole EM telemetry system or both)using both lower carrier frequencies and higher carrier frequencies.These signals may be transmitted in sequence or at the same time. If thehigher frequency signal is successfully received at its destination,then it can be acted on without waiting until the lower-frequency signalhas been received. One of the frequencies used may be an extra lowfrequency that is most likely to be detected under worst-caseconditions. The other signal may be transmitted at a higher frequency.

For example, where a downhole EM telemetry system receives downlink datasent using a high-frequency EM telemetry signal, then the downhole EMtelemetry system can configure itself according to commands in thedownlink signal data without waiting for completion of the transmissionof the same commands on the lower frequency signal.

Similarly, where a driller is waiting for data (e.g. toolface data) toproceed then, if the data sent using a high-frequency EM telemetrysignal is successfully received from the downhole EM telemetry system,the driller does not need to wait to receive the same data by way of thelower-frequency EM telemetry transmission. As soon as the driller hasreceived the required data, the driller may recommence drilling. In someembodiments, where the low frequency transmission is continuing at thetime when the driller commences drilling, the low frequency transmissionmay be truncated in response to detecting rotation of the drill string.

In some embodiments, an EM telemetry protocol may specify that data tobe transmitted by the downhole EM telemetry system should be split upand transmitted using different EM telemetry frequencies (eithersimultaneously or in a given sequence). Signals detected at the surfacemay be filtered to separate the different frequencies. A differentfilter may be provided for each frequency.

In some embodiments, where the system determines from the result of asweep or otherwise that multiple EM telemetry frequencies are availableto use, the system may be configured to simultaneously send data by EMtelemetry using two or more different carrier frequencies. In caseswhere the priority is low-latency communication, higher priority datamay be sent using the highest frequency and lower priority data may besent using lower frequencies. At the surface, data received on differentfrequencies may be separated using suitable filters and then separatelyand simultaneously displayed, stored and/or otherwise processed. Incases where the priority is given to reliable communication, then higherpriority data may be sent using one or more lower frequencies and lowerpriority data may be sent using higher frequencies.

In some embodiments, during flow off conditions when the well is quiet,data throughput may be increased to transmit certain data (e.g. loggingor survey data) more quickly. Such data may be transmitted using an EMtelemetry protocol that provides a higher data rate (at the possiblecost of increased power consumption) to reduce the time required totransmit the data to the surface. After the survey data or a desiredportion of the survey data has been transmitted, then the system mayswitch to an alternative EM telemetry protocol that provides reducedpower consumption.

Some embodiments make use of other modes of telemetry in addition to EMtelemetry. For example, mud pulse telemetry may be used to transmitdownlink signals and/or to transmit uplink signals. This capability maybe used to allow communication to or from the downhole EM telemetrysystem to be made reliably and yet provide at least one mode ofcommunication which has a relatively low latency to achieve rapidresponse of the downhole EM telemetry system. For example, rapid changesin the behaviour of the downhole EM telemetry system, e.g. switchingbetween configuration files, could be achieved very quickly using fastEM downlink telemetry. Data that is less time sensitive to betransmitted to the EM telemetry system may be transmitted by a slower,but possibly more reliable in all circumstances, mode of datatransmission. Transmission by different modes may occur simultaneously(concurrently) or overlapping in time or may be done at different times.

In some embodiments, selection of the appropriate data transmissionprotocol is based at least in part on the current state of charge ofdownhole batteries powering the electromagnetic telemetry system.

In some embodiments, sweeps themselves are used to encode data. Forexample, the order in which the different frequencies are transmittedand/or the amplitudes at which the different frequencies are transmittedand/or the number of cycles of each different frequency transmitted maybe varied in such a way as to encode data. This data may be received atthe surface. This data may, for example, comprise: an encoding schemethat will be used for encoding transmitted data by way of EM telemetry;data to be transmitted (e.g. tool face data); data regarding the statusof the downhole EM telemetry system or another downhole system; or thelike.

In some embodiments, frequencies which are not likely to be received areomitted from a sweep. For example, once a wellbore has been drilled to adepth such that the highest frequencies in a sweep are no longer beingreceived, the highest frequency or frequencies may be left out of thesweep to conserve time and power. In some embodiments, the highestfrequencies are still transmitted once in every few sweeps or everyother sweep or the like in case conditions have changed such that thehighest frequencies are again able to be received. In another exampleembodiment, where there is electrical noise that renders a frequencyunusable for EM telemetry or undesirable, then that frequency may beleft out of the sweep.

Embodiments as described herein transmit EM signals with multiplefrequencies from a downhole location. In addition to application inevaluating the most appropriate frequency to use for EM telemetry, suchsignals may also be applied to cause interference with EM telemetry inadjoining wells. Since directional drilling can be used to makewellbores that extend for long distances horizontally, an operator of adirectional drilling rig may deliberately or inadvertently drill awellbore that extends into a formation that the operator is not entitledto drill into (e.g. a formation on an adjacent lease). The technologydescribed herein may be applied to generate EM signals that interferewith EM telemetry from such a rogue operator and prevent the drilling ofa wellbore assisted by EM telemetry in the vicinity of a wellbore inwhich sweeps are being generated as described above.

In some embodiments, surface equipment includes filters configured toblock frequencies other than those frequencies being used for datatelemetry from downhole. Since the frequency or frequencies allocatedfor data telemetry may change from time to time, as described herein,the filters at the surface equipment may be re-set to pass the currentdata telemetry signal frequencies. This resetting may be performedautomatically each time new data telemetry signal frequencies areselected.

In some embodiments, data telemetry signal frequencies are selectedbased in part on signal-to-noise ratio on different frequencies. Noisemay come from drill rig equipment, telemetry in an adjacent well (by arogue operator or otherwise) or other sources. In some embodiments, inresponse to identifying frequencies on which significant noise ispresent (e.g. noise exceeding a threshold and/or SNR lower than athreshold), a blocking filter is automatically configured at the surfaceequipment to block the noisy frequency(ies) and other frequencies areselected for data telemetry. Such noisy frequency(ies) may be identifiedin analyzing a received sweep signal as described above.

A sweep signal may be received at a location other than surfaceequipment. For example, a sweep signal sent by a first piece of downholeequipment may be detected by a second piece of downhole equipment spacedapart along the drill string from the first piece of downhole equipment.A sweep signal generated at one location may be received at two or moreother locations. These possibilities facilitate a number of possibleapplications. One possible application is setting different EM telemetryparameters for communications to different endpoints. For example, adownhole probe may use one set of EM telemetry parameters(frequency(ies), data encoding scheme, etc.) for communication tosurface equipment and another set of EM telemetry parameters forcommunication to another downhole probe. Each set of EM telemetryparameters may be selected based on received sweep signals according tomethods as described herein.

A plurality of pieces of downhole equipment may be configured togenerate sweep signals and to receive sweep signals generated by otherpieces of downhole equipment. An application of this possibility is tomap the hole for regions in which EM transmissions are stronglyattenuated. For example, consider the case where there are several (e.g.4 to 10 systems) spaced apart along the drill string, each capable ofgenerating sweep signals and receiving sweep signals. When a zone ofhigh EM signal attenuation is located between the two systems that arefarthest downhole, the two farthest downhole systems may detectattenuated sweep signals from one another but the other systems may notdetect the sweep signals from the farthest downhole system because ofthe high attenuation. Information regarding the locations of zones ofhigh attenuation may be used to predict attenuation along the entirelength of the wellbore. This information may be applied to selectingtelemetry types (e.g. EM telemetry may be disabled for a system that islocated in a zone of high attenuation and other telemetry types—e.g. mudpulse telemetry—may be used instead).

While a number of exemplary aspects and embodiments have been discussedabove, those of skill in the art will recognize certain modifications,permutations, additions and sub-combinations thereof. It is thereforeintended that the following appended claims and claims hereafterintroduced are interpreted to include all such modifications,permutations, additions and sub-combinations as are within their truespirit and scope.

Interpretation of Terms

Unless the context clearly requires otherwise, throughout thedescription and the claims:

-   -   “comprise”, “comprising”, and the like are to be construed in an        inclusive sense, as opposed to an exclusive or exhaustive sense;        that is to say, in the sense of “including, but not limited to”.    -   “connected”, “coupled”, or any variant thereof, means any        connection or coupling, either direct or indirect, between two        or more elements; the coupling or connection between the        elements can be physical, logical, or a combination thereof.    -   “herein”, “above”, “below”, and words of similar import, when        used to describe this specification shall refer to this        specification as a whole and not to any particular portions of        this specification.    -   “or”, in reference to a list of two or more items, covers all of        the following interpretations of the word: any of the items in        the list, all of the items in the list, and any combination of        the items in the list.    -   the singular forms “a”, “an”, and “the” also include the meaning        of any appropriate plural forms.

Words that indicate directions such as “vertical”, “transverse”,“horizontal”, “upward”, “downward”, “forward”, “backward”, “inward”,“outward”, “vertical”, “transverse”, “left”, “right”, “front”, “back”,”“top”, “bottom”, “below”, “above”, “under”, and the like, used in thisdescription and any accompanying claims (where present) depend on thespecific orientation of the apparatus described and illustrated. Thesubject matter described herein may assume various alternativeorientations. Accordingly, these directional terms are not strictlydefined and should not be interpreted narrowly.

Where a component (e.g. a circuit, module, assembly, device, drillstring component, drill rig system, etc.) is referred to above, unlessotherwise indicated, reference to that component (including a referenceto a “means”) should be interpreted as including as equivalents of thatcomponent any component which performs the function of the describedcomponent (i.e., that is functionally equivalent), including componentswhich are not structurally equivalent to the disclosed structure whichperforms the function in the illustrated exemplary embodiments of theinvention.

Specific examples of systems, methods and apparatus have been describedherein for purposes of illustration. These are only examples. Thetechnology provided herein can be applied to systems other than theexample systems described above. Many alterations, modifications,additions, omissions and permutations are possible within the practiceof this invention. This invention includes variations on describedembodiments that would be apparent to the skilled addressee, includingvariations obtained by: replacing features, elements and/or acts withequivalent features, elements and/or acts; mixing and matching offeatures, elements and/or acts from different embodiments; combiningfeatures, elements and/or acts from embodiments as described herein withfeatures, elements and/or acts of other technology; and/or omittingcombining features, elements and/or acts from described embodiments.

It is therefore intended that the following appended claims and claimshereafter introduced are interpreted to include all such modifications,permutations, additions, omissions and sub-combinations as mayreasonably be inferred. The scope of the claims should not be limited bythe preferred embodiments set forth in the examples, but should be giventhe broadest interpretation consistent with the description as a whole.

What is claimed is:
 1. A method for downhole electromagnetic (EM)telemetry in a downhole drilling operation, the method comprising thesteps of: determining a mode of the drilling operation; sending a set ofEM sweep signals from a downhole EM telemetry system located at adownhole location to an uphole system located at a surface location,each of the EM sweep signals having a different frequency; determiningwhether each of the EM sweep signals is received at the uphole systemand, for the EM sweep signals received, measuring parameters of thereceived EM sweep signals, the parameters comprising at least one ofsignal strength and signal-to-noise-ratio; based at least in part on:the mode of drilling operation, the EM sweep signals received, and theparameters measured, determining a protocol for downhole datatransmission, the protocol specifying protocol parameters including oneor more of signal frequency, signal amplitude, and data encoding scheme;and configuring the downhole EM telemetry system to transmit data to theuphole system using the protocol.
 2. A method according to claim 1wherein the data encoding scheme comprises: one of QPSK (quadraturephase shift keying); BPSK (binary phase shift keying); PSK (phase-shiftkeying); FSK (frequency-shift keying); QAM (quadrature amplitudemodulation); 8ASK (8 amplitude shift keying); and APSK (amplitude phaseshift keying).
 3. A method according to claim 1 wherein the dataencoding scheme specifies a number of cycles to use to transmit datasymbols.
 4. A method according to claim 3 wherein the method sets thenumber of cycles to use to transmit each symbol based on the measuredsignal-to-noise ratio for one of the EM sweep signals.
 5. A methodaccording to claim 1 comprising: determining, based at least in part onthe EM sweep signals received and the parameters measured, whether thesignal strength exceeds a threshold, and if the signal strength exceedsthe threshold, adjusting the protocol by increasing the signalfrequency.
 6. A method according to claim 1 comprising determining,based at least in part on the EM sweep signals received and theparameters measured, whether the signal strength exceeds a threshold,and if the signal strength exceeds the threshold, adjusting the protocolby reducing the signal amplitude.
 7. A method according to claim 1comprising determining, based at least in part on the EM sweep signalsreceived and the parameters measured, whether the signal strengthexceeds a threshold, and if the signal strength exceeds the threshold,adjusting the protocol by reducing the signal amplitude and increasingthe signal frequency.
 8. A method for downhole electromagnetic (EM)telemetry in a downhole drilling operation, the method comprising thesteps of: in response to determining that a drilling operation is in aquiet mode wherein a flow of drilling fluid is off and a drill string isnot being rotated, configuring a downhole EM telemetry system totransmit data to an uphole system using a first protocol that transmitsdata at a first data rate; transmitting first data using the firstprotocol; after transmitting the first data configuring the downhole EMtelemetry system to transmit data to the uphole system using a secondprotocol that transmits data at a second data rate lower than the firstdata rate; and transmitting second data using the second protocolwherein the first protocol and the second protocol differ by one or moreof: different EM signal frequencies; different numbers of cycles per bitand different data encoding schemes.
 9. A method according to claim 8wherein the first data comprises survey data.
 10. A method according toclaim 9 comprising configuring the downhole EM telemetry system totransmit data to the uphole system using the first protocolconditionally on there being survey data available for transmission atthe downhole system.
 11. A method according to claim 8 comprisingautomatically switching to the second protocol after all or apredetermined amount or proportion of the survey data available fortransmission at the downhole system has been transmitted using the firstprotocol.
 12. A method according to claim 8 wherein the second protocoluses less electrical power per bit of transmitted data than the firstprotocol.
 13. A method according to claim 8 wherein the first protocoluses two or more transmit frequencies and the second protocol uses asingle transmit frequency.
 14. A downhole EM telemetry systemcomprising: a control circuit, an EM signal transmitter; a plurality ofEM telemetry protocols, each of the EM telemetry protocols specifyingone or more of: signal frequency, signal amplitude, and data encodingscheme; and one or more sensors; wherein the control circuit isconfigured to receive signals from the one or more sensors and to applyone of the plurality of EM telemetry protocols for transmission of databy the EM signal transmitter based on the received signals, wherein oneof the received signals comprises a signal indicating the mode ofdrilling operation and the control circuit is configured to select theone of the EM telemetry protocols based at least in part on the mode ofdrilling operation.
 15. A system according to claim 14 wherein the dataencoding scheme of at least one of the protocols comprises: one of QPSK(quadrature phase shift keying); BPSK (binary phase shift keying); PSK(phase-shift keying); FSK (frequency-shift keying); QAM (quadratureamplitude modulation); 8ASK (8 amplitude shift keying); and APSK(amplitude phase shift keying).
 16. A system according to claim 14wherein the data encoding scheme of at least one of the protocolsspecifies a number of cycles to use to transmit data symbols.
 17. Asystem according to claim 14 wherein the control circuit is configuredto set the number of cycles to use to transmit each symbol based on themeasured signal-to-noise ratio for one of the EM sweep signals.
 18. Asystem according to claim 14 wherein the control circuit is configuredto determine, based at least in part on the EM sweep signals receivedand the parameters measured, whether the signal strength exceeds athreshold, and if the signal strength exceeds the threshold, to performone or more of reducing the signal amplitude and increasing the signalfrequency.
 19. An EM telemetry system for communicating signals in awellbore between a surface location and a downhole location, the EMtelemetry system comprising: a signal generator configured to send a setof EM sweep signals at the downhole location; a receiver configured toreceive the EM sweep signals at the surface location; and a processor incommunication with the receiver and the signal generator, the processorconfigured to determine whether each of the EM sweep signals in the setis received at the receiver and, for each of the EM sweep signalsreceived, record parameters of the EM sweep signal, the parameterscomprising at least one of signal strength and signal-to-noise ratio;the processor further configured to determine a mode of the drillingoperation; the processor further configured to determine a protocol fordata transmission between the downhole location and the surface locationbased at least in part on the mode of the drilling operation, the EMsweep signals received, and the parameters recorded, the protocolcomprising protocol parameters including one or more of signalfrequency, signal amplitude, and data encoding scheme and to communicatethe determined protocol to the signal generator.
 20. The systemaccording to claim 19 comprising a downlink transmission system coupledto the processor and the signal generator, the downlink transmissionsystem configured to communicate the determined protocol to the signalgenerator.